Method and system for handling producing fluid

ABSTRACT

Production fluid is received in a seabed facility ( 3 ) from a hydrocarbon reservoir and water is separated from the production fluid by a fluid separator vessel ( 15 ) in the seabed facility ( 3 ). The production fluid is then conveyed to a host facility ( 2 ) by a production fluid pipeline ( 4 ). The separated water enters a fluid clean-up unit ( 19 ) which removes hydrocarbons from the water, and the water is then passed through a photo-chromatic device ( 20 ) which measures the amount of oil in the water. Providing that the water is measured to contain not more than the predetermined threshold maximum limit of oil in water, it is disposed of into the sea surrounding the seabed facility ( 3 ).

The present invention relates to a method and system for handlingproduction fluid extracted from a hydrocarbon reservoir.

In a developed oil or gas field, wells are used to extract productionfluid, comprising hydrocarbon fluid and water, from the hydrocarbonreservoir and the production fluid is conveyed to a host facility fromthe wells via a production pipeline.

However, the reservoir may not have enough pressure to drive theproduction fluid to the host facility. To overcome this problem apipeline is provided which conveys injection water from the hostfacility at a pressure higher than the reservoir pressure to a seabedfacility at which it is manifolded to connected water injection wellsfor injection into the reservoir. However, this increases the percentageof water already in the production fluid which means that the productionfluid pipeline to the host facility has to be of a sufficient size toconvey production fluid including the water naturally occurring thereinand the injected water. This makes such a pipeline expensive.

It is therefore an object of the present invention to provide a methodand system which overcomes at least the above-mentioned disadvantage ofthe prior art.

According to one aspect of the present invention there is provided amethod for handling production fluid, comprising the steps of:

-   -   receiving production fluid in an underwater facility from a        hydrocarbon reservoir;    -   separating water from the production fluid in the underwater        facility; and    -   disposing of the water below the surface of the water in which        the underwater facility is located.

By separating the water from the production fluid and disposing of thewater below the surface of the water, the production fluid pipeline,which connects the underwater facility to the host facility, may bespecified to be of a smaller diameter as it only needs to transportwater free production fluid to the host facility.

Removal of the water from the production fluid removes a significantsource of corrosion of the production fluid pipeline which may enablethe pipeline to be of a lower grade, less noble or cheaper material. Theremoval of the water also reduces the possibility of hydrate formationin the pipeline as the production fluid cools. This results in lesschemical injection from the host facility into the production fluidbeing required. Thus, a pipeline for supplying the injected chemicalsfrom the host facility to the production fluid pipeline can be reducedin diameter, and less equipment for chemical injection is required atthe host facility.

If pressure boosting of the production fluid is required at theunderwater facility to drive it to the host facility, the pump requiredcan be smaller than that required when the production fluid containswater, as there is less fluid to be pumped to the host facility.Furthermore, this means that less power is required to be generated atthe host facility to drive the pump at the underwater facility, whichenables the umbilical for supplying power from the host facility to thepump to be of a reduced specification.

Hence, the invention provides considerable cost savings. There are alsosavings in deck space on the host facility and in the weight to besupported by the host facility.

The savings in pipeline costs enables longer tie-backs to the hostfacility to be economically considered which may allow the use of anexisting host facility to be used as opposed to having to provide a newhost facility. This is of particular benefit when the field to bedeveloped is located beneath deep water.

The percentage of water in the production fluid continues to increaseover the life of the field to the point where the field becomesuneconomic to continue, because the production fluid only comprises asmall percentage of hydrocarbons. As the percentage of hydrocarbons inthe production fluid diminishes over the life of the field, theproduction fluid pipeline will have spare capacity as it is no longerrequired to transport water. Hence, the pipeline enables additionaldevelopments of the existing field or developments of a new field to betied in to the underwater facility to use this spare capacity avoidingthe need to lay a new pipeline to the host facility. Any well of a newdevelopment may be “daisy chained” to the underwater facility.

Before the step of disposing of the water, there may be included thestep of purifying the water separated from the production fluid.

Before the step of disposing of the water, there may be included thestep of measuring the purity of the water. Furthermore, a subsequentstep may be included in which the purified water is returned back forfurther purification when the result of measuring the water purityreveals that it has a purity level below a predetermined thresholdlevel. The measuring step may comprise measuring the amount of oil inwater.

The step of disposing of the water may comprise disposing of the waterinto the water in which the underwater facility is located.

The step of disposing of the water may include injecting the water intothe reservoir. This may include the additional step of combining thewater with injection fluid from a host facility before injection intothe hydrocarbon reservoir. The water for disposal may be purified beforebeing combined with injection fluid from the host facility to avoid thechemical composition of the water causing undesirable chemical reactionswhich would affect production.

The step of disposing of the water may include injecting the water intoa disposal well.

According to another aspect of the present invention there is provided asystem for handling production fluid, comprising an underwater facilityhaving production fluid separation means for receiving production fluidfrom a hydrocarbon reservoir and separating water from the productionfluid, and disposal means for disposing of the water from the underwaterfacility to below the surface of the water in which the underwaterfacility is located.

The underwater facility preferably includes water purification means forpurifying water separated from the production fluid by the separationmeans before the water is disposed of by the disposal means.

There may be provided a measuring device between the water purificationmeans and the disposal means for measuring the purity of the purifiedwater. The underwater facility may have recirculation means fordelivering purified water back to the water purification means when theresult of measuring the water purity reveals that it has a purity levelbelow a predetermined threshold level. The measuring device may measurethe amount of oil in the water. The measuring device may comprise aphotochromatic device.

The disposal means may be arranged to dispose of the water into thewater in which the underwater facility is located.

The disposal means may include a connector for enabling the disposalmeans to be connected to a disposal well or to the hydrocarbonreservoir.

There may be provided a retrievable module for an underwater processingsystem, the module comprising the system described above. Theretrievable module enables the equipment within it to be easilyrecovered for inspection, maintenance or repair without interruptingoperations. The module may be of the type forming part of the modularsystem designed by Alpha Thames Ltd of Essex, United Kingdom and namedAlpha PRIME.

Embodiments of the present invention will now be described, by way ofexample, with reference to the accompanying drawings, in which:

FIG. 1 is a schematic diagram of a system for putting the invention intopractice:

FIGS. 2 and 3 are schematic diagrams illustrating modified systems; and

FIGS. 4 to 6 are details of FIGS. 1 to 3, respectively.

Referring to FIGS. 1 and 4 of the accompanying drawings, a system 1 hasa host facility which may be, for example, onshore or on a fixed orfloating rig. The host facility 2 is connected to a remote seabedfacility 3 by a production fluid pipeline 4 and a water injectionpipeline 5. The seabed facility 3 is connected to a plurality of wells6,7 for a hydrocarbon reservoir whereby each well is connected to thefacility 3 by a separate fowline 8,9. Some of these wells are productionwells 6 and the remaining wells are water injection wells 7.

The seabed facility 3 has a base structure 10 to which the productionfluid pipeline 4 and the water injection line 5 are connected. At thebase structure 10 the water injection line 5 is connected to theflowlines 9 to the water injection wells 7. Also, at the base structure10, the flowlines 8 from the production wells 6 are manifolded to asingle conduit 11.

The base structure 10 supports a retrievable module 12 which isconnected to the manifold conduit 11 and the production fluid pipeline 4by a multi-ported fluid connector 13 such as that described inGBA-2261271 which enables the module 12 to be isolated from all thepipelines 4,5 and flowlines 8,9 connected to the seabed facility 3 whenthe module 12 is to be retrieved.

The manifold conduit 11 is connected to an inlet 14 of a two-phase fluidseparator vessel 15 in the module 12 via the fluid connector 13. A firstoutlet 16 of the fluid separator vessel 15 is connected to theproduction fluid pipeline 4 via the fluid connector 13. A second outlet17 of the vessel 15 is connected to a port 18 on the outside of themodule 12 via a fluid clean-up unit 19 and a fluid monitoring device 20.An example of such a fluid clean-up unit is the TORE SEP and de-oilinghydrocyclone package available from Merpro Ltd of Bristol, UnitedKingdom and an example of such a fluid monitoring device is the JORINVIPA metering device available from Jorin Ltd of Berkshire, UnitedKingdom. There is also a recirculation pipe 21 between the fluidmonitoring device 20 and the fluid clean-up unit 19.

The operation of the system 1 will now be described.

The host facility 2 injects water into the hydrocarbon reservoir via thewater injection pipeline 5, the flowlines 9 and the water injectionwells 7. The injected water drives the production fluid at an increasedpressure to the seabed facility 3 via the production wells 6 andflowlines 8.

At the seabed facility 3, the fluid separator vessel 15 receives theproduction fluid 6 from the production wells and separates water fromthe production fluid. The at least substantially water free productionfluid leaves the fluid separator vessel 15 by the first outlet 16 and isconveyed to the host facility 2 by the production fluid pipeline 4. Theseparated water leaves the separator vessel 15 by the second outlet 17and enters the fluid clean-up unit 19 which removes hydrocarbons fromthe water. The cleaned water is then passed through the fluid monitoringdevice 20, such as a photo-chromatic device, which measures the amountof oil in the water. The fluid monitoring device 20 is used to ensurethat the cleaned water is sufficiently clean so that it can be disposedof into the sea surrounding the module via the port 18, the cleanedwater may be pressure boosted by a pump 24 before disposal. If the wateris measured to contain more than the legislated allowable maximum limitof oil in water then the water is not sufficiently clean for disposaland is instead returned to the fluid clean-up unit 19 for furthercleaning via the recirculation pipe 21.

Modifications to the system 1 will now be described in which parts whichcorrespond to those shown in FIG. 1 are designated with the samereference numerals and are not described in detail below.

FIGS. 2 and 5 illustrate one modification to the system 1. In themodified system 22, the second outlet 17 of the fluid separator vessel15 is connected by a conduit 23 to the water injection pipeline 5 at thebase structure 10 via the pump 24, the fluid connector 13 and anon-return valve 28, the latter preventing fluid from the pipeline 5from entering the separator vessel 15 via the second outlet 17. At thebase structure 10, the water injection pipeline 5 has a non-return valve29 upstream of the conduit 23 connected to the separator vessel 15. Thisprevents separated fluid from the separator vessel 15 flowing up thepipeline 5 towards the host facility 2. The non-return valves 28,29 havebeen omitted from FIG. 2 for clarity. In use, water separated from theproduction fluid is conveyed by the conduit 23 into the water injectionpipeline 5 where it is combined with water from the host facility 2 forinjection into the hydrocarbon reservoir via the water injection wells7.

FIGS. 3 and 6 illustrate a modification to the system 22 shown in FIG.2. In the modified system 25, a disposal well 26 is connected to thebase structure 10 by a flowline 27 and the second outlet 17 of theseparator vessel 15 is connected to this flowline 27 via the pump 24 andthe fluid connector 13. Thus, water separated from the production fluidis disposed of by being injected into the disposal well 26.

The disposal well 26 may, for example, inject water into the hydrocarbonreservoir or into an aquifer beneath the seabed and there may be aplurality of disposal wells connected to the base structure 10 of theseabed facility.

Whilst particular embodiments have been described, it will be understoodthat various modifications may be made without departing from the scopeof the invention. For example, the seabed facility 3 may be located at awellhead of a well. The pipelines and flowlines described may be ofrigid or flexible construction.

In the first embodiment, a pump may not be required to pump water intothe sea. However, this is dependent upon the depth of the seabedfacility where a pump is more likely to be required at greater depths.

1. A method for handling production fluid, comprising the steps of:receiving production fluid in an underwater facility (3) from ahydrocarbon reservoir; separating water from the production fluid in theunderwater facility (3); and disposing of the water below the surface ofthe water in which the underwater facility (3) is located.
 2. A methodas claimed in claim 1, including the step of purifying the waterseparated from the production fluid before the step of disposing of thewater.
 3. A method as claimed in claim 2, including the step ofmeasuring the purity of the water before the step of disposing of thewater.
 4. A method as claimed in claim 3, including returning thepurified water back for further purification when the result ofmeasuring the water purity reveals that it has a purity level below apredetermined threshold level.
 5. A method as claimed in claim 3,wherein the measuring step comprises measuring the amount of oil inwater.
 6. A method as claimed in claim 1, wherein the step of disposingof the water comprises disposing of the water into the water in whichthe underwater facility (3) is located.
 7. A method as claimed in claim1, wherein the step of disposing of the water includes injecting thewater into the hydrocarbon reservoir.
 8. A method as claimed in claim 7,including the additional step of combining the water with injectionfluid from a host facility (2) before injection into the hydrocarbonreservoir.
 9. A method as claimed in claim 1, wherein the step ofdisposing of the water comprises injecting the water into a disposalwell (26).
 10. A system (1) for handling production fluid, comprising anunderwater facility (2) having production fluid separation means (15)for receiving production fluid from a hydrocarbon reservoir andseparating water from the production fluid, and disposal means (18,24)for disposing of the water from the underwater facility to below thesurface of the water in which the underwater facility is located.
 11. Asystem as claimed in claim 10, wherein the underwater facility (2)includes water purification means (19) for purifying water separatedfrom the production fluid by the separation means (15) before the wateris disposed of by the disposal means (18,24).
 12. A system as claimed inclaim 11, including a measuring device (20) between the waterpurification means (19) and the disposal means (18,24) for measuring thepurity of the purified water.
 13. A system as claimed in claim 12,wherein the underwater facility (2) has recirculation means (21) fordelivering purified water back to the water purification means (19) whenthe result of measuring the water purity reveals that it has a puritylevel below a predetermined threshold level.
 14. A system as claimed inclaim 12, wherein the measuring device (20) is arranged to measure theamount of oil in the water.
 15. A system as claimed in claim 12, whereinthe measuring device (20) comprises a photochromatic device.
 16. Asystem as claimed in claim 10, wherein the disposal means (18,24) isarranged to dispose of the water into the water in which the underwaterfacility (3) is located.
 17. A system as claimed in claim 10, whereinthe disposal means includes a connector (13) for enabling the disposalmeans (23,24) to be connected to a disposal well (26) or to thehydrocarbon reservoir.
 18. A retrievable module (12) for an underwaterprocessing system, the module comprising the system as claimed in claim10.